Method of using a sized barite as a weighting agent for drilling fluids

ABSTRACT

An additive that increases the density of fluids containing a sized barite weighting agent. The wellbore fluid has rheological properties comparable to a conventional wellbore fluids but does not exhibit problems with sag and resulting variations in density. An illustrative embodiment is directed to a method for making the sized barite weighting agent and a method for using such sized barite weighting agent in a wellbore fluid. In one preferred embodiment the sized barite weighting agent has a particle diameter between 4 μm to 15 μm In another preferred embodiment, the additive has a D 50  (by weight) of approximately 1 μm to 6 μm. In another preferred embodiment the additive has a D 90  (by weight) of approximately 4 μm to 8 μm. The additive may be used in any wellbore fluid such as drilling, cementing, completion, packing, work-over (repairing), stimulation, well killing, and spacer fluid.

This application claims the benefit of U.S. Provisional Application No.60/576,420 filed Jun. 3, 2004, incorporated herein by reference.

BACKGROUND

A wellbore fluid serves many important functions throughout the processin drilling for oil and gas. One such function is cooling andlubricating the drill bit as it grinds though the earth's crust. As thedrill bit descends, it generates “cuttings,” or small bits of stone,clay, shale, or sand. A wellbore fluid serves to transport thesecuttings back up to the earth's surface. As drilling progresses, largepipes called “casings” are inserted into the well to line the boreholeand provide stability. One of skill in the art should appreciate thatthese uncased sections of the borehole, which are exposed to the highpressures of the reservoir, must be stabilized before casing can be set;otherwise, a reservoir “kick” or, in the extreme case, a “blowout”—acatastrophic, uncontrolled inflow of reservoir fluids into thewellbore—may occur. A wellbore fluid, if monitored properly, can providesufficient pressure stability to counter this inflow of reservoirfluids.

A critical property differentiating the effectiveness of variouswellbore fluids in achieving these functions is density, or mass perunit volume. The wellbore fluid must have sufficient density in order tocarry the cuttings to the surface. Density also contributes to thestability of the borehole by increasing the pressure exerted by thewellbore fluid onto the surface of the formation downhole. The column offluid in the borehole exerts a hydrostatic pressure (also known as ahead pressure) proportional to the depth of the hole and the density ofthe fluid. Therefore, one can stabilize the borehole and prevent theundesirable inflow of reservoir fluids by carefully monitoring thedensity of the wellbore fluid to ensure that an adequate amount ofhydrostatic pressure is maintained.

It has been long desired to increase the density of wellbore fluids,and, not surprisingly, a variety of methods exist. One method is addingdissolved salts such as sodium chloride, calcium chloride, and calciumbromide in the form of an aqueous brine to wellbore fluids. Anothermethod is adding inert, high-density particulates to wellbore fluids toform a suspension of increased density. These inert, high-densityparticulates often are referred to as “weighting agents” and typicallyinclude powdered minerals of barite, calcite, or hematite.

Naturally occurring barite (barium sulfate) has been utilized as aweighting agent in drilling fluids for many years. Drilling grade bariteis often produced from barium sulfate containing ores either from asingle source or by blending material from several sources. It maycontain additional materials other than barium sulfate mineral and thusmay vary in color from off-white to grey or red brown. The AmericanPetroleum Institute (API) has issued international standards to whichground barite must comply. These standards can be found in APISpecification 13A, Section 2.

Other materials, such as finely divided metals have been used asweighting agents for wellbore fluids, such as found in PCT PatentApplication WO085/05118, which discloses using iron ball-shapedparticles having a diameter less than 250 μm and preferably between 15and 75 μm, and calcium carbonate and iron carbonate, as disclosed inU.S. Pat. No. 4,217,229, have also been proposed as weighting agents.

It is known in the art that during the drilling process weightingagents, as well as cuttings, can create sedimentation or “sag” that canlead to a multitude of well-related problems such as lost circulation,loss of well control, stuck pipe, and poor cement jobs. The sagphenomenon arises from the settling out of particles from the wellborefluid. This settling out causes significant localized variations in muddensity or “mud weight,” both higher and lower than the nominal ordesired mud weight. The phenomenon generally arises when the wellborefluid is circulating bottoms-up after a trip, logging or casing run.Typically, light mud is followed by heavy mud in a bottoms-upcirculation.

Sag is influenced by a variety of factors related to operationalpractices or drilling fluid conditions such as: low-shear conditions,drillstring rotations, time, well design, drilling fluid formulation andproperties, and the mass of weighting agents. The sag phenomenon tendsto occur in deviated wells and is most severe in extended-reach wells.For drilling fluids utilizing particulate weighting agents, differentialsticking or a settling out of the particulate weighting agents on thelow side of the wellbore is known to occur.

Particle size and density determine the mass of the weighting agents,which in turn correlates to the degree of sag. Thus it follows thatlighter and finer particles, theoretically, will sag less. However, theconventional view is that reducing weighting agent particle size causesan undesirable increase in the fluid's viscosity, particularly itsplastic viscosity. Plastic viscosity is generally understood to be ameasure of the internal resistance to fluid flow that may beattributable to the amount, type or size of the solids present in agiven fluid. It has been theorized that this increase in plasticviscosity attributable to the reduction in particle size—and therebyincreasing the total particle surface area—is caused by a correspondingincrease in the volume of fluids, such as water or drilling fluid,adsorbed to the particle surfaces. Thus, particle sizes below 10 μm havebeen disfavored.

Because of the mass of the weighting agent, various additives are oftenincorporated to produce a rheology sufficient to allow the wellborefluid to suspend the material without settlement or “sag” under eitherdynamic or static conditions. Such additives may include a gellingagent, such as bentonite for water-based fluid or organically modifiedbentonite for oil-based fluid. A balance exists between adding asufficient amount of gelling agent to increase the suspension of thefluid without also increasing the fluid viscosity resulting in reducedpumpability. One may also add a soluble polymer viscosifier such asxanthan gum to slow the rate of sedimentation of the weighting agent.

Various approaches exist in the art to provide a wellbore fluid with thedesired density with a minimum impact on its fluid properties, or“rheology.” One approach has been disclosed in U.S. Pat. No. 6,180,573which involved purposefully removing some or all of the finest particlesfrom a ground barite (i.e. particles below 6 μm), and then monitoringand maintaining the selected particle size by adding coarser material asthe particle size degrades during use.

It is worth noting that, despite the general industry disfavor, otherapproaches have used small particles as weighting agents. One approach,disclosed in U.S. Pat. No. 5,007,480, uses manganomanganic oxide (Mn₃O₄)having a particle size of at least 98% below 10 μm in combination withconventional weighting agents such as API grade barite, which results ina drilling fluid of higher density than that obtained by the use ofbarite or other conventional weighting agents alone. Another approach isdisclosed in EP-A-119 745, which describes an ultra high-density fluidfor blowout prevention comprised of water, a first and possible secondweighting agent, and a gellant made of fine particles of averagediameter between 0.5 and 10 μm. The gelling agent particles are smallenough to impart good static gel strength to the fluid by virtue ofinterparticle attractive forces. Yet another approach is disclosed inU.S. patent application 20040127366, the specification of which isincorporated by reference herein, which discloses a weighting agenthaving a weight average particle diameter of less than 1.5 μm and coatedwith a dispersant for controlling the interparticle interactions,thereby minimizing any increase in viscosity incurred by the use ofSIZED particles.

The need exists to provide a high-density fluid that has an improved sagperformance as compared to conventional fluids, while maintainingcomparable rheological properties.

SUMMARY

An illustrative embodiment of the claimed subject matter is generallydirected to an sized weighting agent and a wellbore fluid containingsuch sized weighting agent that has an increased density with improvedsuspension stability without a significant viscosity increase such thatthe wellbore fluid has rheological properties comparable to aconventional wellbore fluid. An illustrative embodiment of the claimedsubject matter is further directed to a method for making the sizedweighting agent and a method for using such sized weighting agent in awellbore fluid. In one illustrative embodiment the sized bariteweighting agent has a particle size distribution such that at least 90%by volume of the measured particle diameter is between about 4 μm andabout 20 μm and preferably is in the range of about 8 μm to about 16 μm.In another illustrative embodiment, the sized barite weighting agentincludes at least 50% by volume particles is preferably in the range ofabout 1 μm to about 10 μm. and preferably in the range of about 4 μm toabout 8 μm.

BRIEF DESCRIPTION OF THE DRAWING

The following Description of Illustrative Embodiments makes reference tothe following drawing:

FIG. 1 Graphically shows the particle size distributions of API bariteand a barite ground in accordance with the teachings of the presentinvention.

DESCRIPTION OF ILLUSTRATIVE EMBODIMENTS

Contrary to conventional belief, using sized barite weighting agent inthe formulation of a wellbore fluid results in rheological properties noless favorable than when using coarser barite weighting material. Thefluid formulation techniques as found in the normal practice of fluidformulations would not generally change. One would still need to adjustthe amounts of dispersants added depending on the mud weight and densityof the fluid and rheological profile that was required in order toachieve a suitable mud formulation. One of skill in the art wouldappreciate the surprising results demonstrating that wellbore fluidscontaining sized barite weighting agents as described herein actuallyprovide superior sag performance to wellbore fluids formulated with thewell-known coarser barite weighting agents. One of skill in the artwould further appreciate the surprising results as described herein thatthe wellbore fluid containing sized barite weighting agents has noappreciable difference in rheologies as compared to wellbore fluidsformulated with well-known coarser barite weighting agents. Inparticular, it has been unexpectedly and surprisingly found that a sizedbarite weighting agent generates high-density suspensions or slurrieswithout the expected increase in plastic viscosity previously associatedwith using finely ground weighting agent particles.

As previously reported in the art, decreasing barite weighting agentparticle sizes were thought to increase the viscosity of the fluid, suchas reported in “Drilling and Drilling Fluids,” Chilingarian G. V. andVorabutor P. 1981, pages 441–444. The reasoning follows, small particleswill adsorb significantly more fluid than larger particles due to theirhigher surface area-to-volume ratio, and because of this higheradsorption of fluid to the surface of the particle, an increase in theviscosity (that is, a decrease in the fluidity) of the wellbore fluid isobserved. Thus, one of skill in the art should understand that it hasgenerally been desirable to eliminate fine barite particles in order toreduce fluid viscosity. This approach to controlling rheology has beendisclosed in U.S. Pat. Nos. 6,180,573 and 6,548,452.

However, wellbore fluids with coarser, larger-sized barite weightingagents are generally formulated with higher rheologies than desired inorder to overcome the problematic issue of barite sag. TABLE 1 shows atypical prior art invert emulsion drilling fluid formulation thatincludes an emulsifier(s), organoclay, lime, and fluid loss additives.As shown in TABLE 1, an internal brine phase is emulsified into acontinuous oil phase by means of a suitable emulsifier package. Thevolume of weighting agent can be adjusted to produce fluids with a rangeof densities and, although a preferred weighting agent is barite, it isfeasible to manufacture drilling or other wellbore fluids with otherknown minerals such as calcium carbonate, hematite, or ilmenite. Asdemonstrated in TABLE 1, various additives typically are used in orderto produce the necessary rheological and filtration characteristics forthe drilling fluid to perform its functions. In particular, the rheologymust be adequate to allow the fluid to suspend the dense weighting agentwithout settlement or “sag” under either dynamic or static conditions. Atypical, non-limiting range of mud weight (MW) is 10–19 lb/gal and anoil to water ratio (OWR) is 60/40 to 95/5.

TABLE 1 (Prior Art) Typical Invert Emulsion Drilling Fluid FormulationTypical Product pounds/barrel Base oil As required Weight Material (i.e.Barite) As required Emulsifier/s 10–20 Organoclay 2–8 Lime  4–10 BrineAs required Fluid Loss Additive 1–5

However, the disclosure herein demonstrates that, contrary toconventional wisdom, one may not need to formulate a wellbore fluid withhigher rheologies than desired to counter the problem of sag. Instead,the sized barite weighting agent as disclosed herein may be used with nosignificant difference in rheology from a drilling fluid using a knowncoarser ground material. And by using a sized barite weighting agent,the particles remain in suspension and therefore provide a superior sagperformance. In view of the art above, one of skill in the art shouldimmediately appreciate the surprising and significant results containedherein, which utilizes barite particles ground to a particle sizedistribution such that at least 90% of the cumulative volume of themeasured particle diameters (d₉₀) is between about 4 μm and about 20 μmand includes at least 50% of the cumulative volume of the measuredparticle diameters (d₅₀) is preferably in the range of about 1 μm toabout 10 μm. As illustrated below such a wellbore fluid exhibits areduced plastic viscosity while at the same time both greatly reducingsedimentation or sag and maintaining comparable rheologies to otherconventional wellbore fluids.

In rotary drilling of subterranean wells numerous functions andcharacteristics are expected of a drilling fluid. A drilling fluidshould circulate throughout the well and carry cuttings from beneath thebit, transport the cuttings up the annulus, and allow their separationat the surface. At the same time, the drilling fluid is expected to cooland clean the drill bit, reduce friction between the drill string andthe sides of the hole, and maintain stability in the borehole's uncasedsections. The drilling fluid should also form a thin, low permeabilityfilter cake that seals openings in formations penetrated by the bit andact to reduce the unwanted influx of formation fluids from permeablerocks.

Drilling fluids are typically classified according to their basematerial. In oil base fluids, solid particles are suspended in oil, andwater or brine may be emulsified with the oil. The oil is typically thecontinuous phase. In water base fluids, solid particles are suspended inwater or brine, and oil may be emulsified in the water. The water istypically the continuous phase.

Invert emulsion fluids, i.e. emulsions in which a non-oleaginous fluidis the discontinuous phase and an oleaginous fluid is the continuousphase, are employed in drilling processes for the development of oil orgas sources, as well as, in geothermal drilling, water drilling,geoscientific drilling and mine drilling. Specifically, the invertemulsion fluids are conventionally utilized for such purposes asproviding stability to the drilled hole, forming a thin filter cake,lubricating the drilling bore and the downhole area and assembly, andpenetrating salt beds without sloughing or enlargement of the drilledhole.

Oil-based drilling fluids are generally used in the form of invertemulsion muds. An invert emulsion mud consists of three-phases: anoleaginous phase, a non-oleaginous phase and a finely divided particlephase. Also typically included are emulsifiers and emulsifier systems,weighting agents, fluid loss additives, viscosity regulators and thelike, for stabilizing the system as a whole and for establishing thedesired performance properties. Full particulars can be found, forexample, in the article by P. A. Boyd et al entitled “New Base Oil Usedin Low-Toxicity Oil Muds” in the Journal of Petroleum Technology, 1985,137 to 142 and in the Article by R. B. Bennet entitled “New DrillingFluid Technology-Mineral Oil Mud” in Journal of Petroleum Technology,1984, 975 to 981 and the literature cited therein. Also reference ismade to the description of invert emulsions found in Composition andProperties of Drilling and Completion Fluids, 5th Edition, H. C. H.Darley, George R. Gray, Gulf Publishing Company, 1988, pp. 328–332, thecontents of which are hereby incorporated by reference.

As used herein the term “oleaginous liquid” means oil which is a liquidat 25.degree. C. and immiscible with water. Oleaginous liquids typicallyinclude substances such as diesel oil, mineral oil, synthetic oil suchas polyolefins or isomerized polyolefins, ester oils, glycerides offatty acids, aliphatic esters, aliphatic ethers, aliphatic acetals, orother such hydrocarbons and combinations of these fluids. In oneillustrative embodiment of this invention the oleaginous liquid is anpolyolefin material which provides environmental degradability to theoverall drilling fluid. Such polyolefins should be selected such thatthe molecular weight permits for a functional invert emulsion drillingfluid to be formulated. Especially preferred are isomerized polyolefinshaving a carbon backbone of 16 to 18 carbons and in which at least onepoint of unstaturation is internal.

The amount of oleaginous liquid in the invert emulsion fluid may varydepending upon the particular oleaginous fluid used, the particularnon-oleaginous fluid used, and the particular application in which theinvert emulsion fluid is to be employed. However, generally the amountof oleaginous liquid must be sufficient to form a stable emulsion whenutilized as the continuous phase. Typically, the amount of oleaginousliquid is at least about 30, preferably at least about 40, morepreferably at least about 50 percent by volume of the total fluid.

As used herein, the term “non-oleaginous liquid” mean any substancewhich is a liquid at 25.degree. C. and which is not an oleaginous liquidas defined above. Non-oleaginous liquids are immiscible with oleaginousliquids but capable of forming emulsions therewith. Typicalnon-oleaginous liquids include aqueous substances such as fresh water,seawater, brine containing inorganic or organic dissolved salts, aqueoussolutions containing water-miscible organic compounds and mixtures ofthese. In one illustrative embodiment the non-oleaginous fluid is brinesolution including inorganic salts such as calcium halide salts, zinchalide salts, alkali metal halide salts and the like.

The amount of non-oleaginous liquid in the invert emulsion fluid mayvary depending upon the particular non-oleaginous fluid used and theparticular application in which the invert emulsion fluid is to beemployed. Typically, the amount of non-oleaginous liquid is at leastabout 1, preferably at least about 3, more preferably at least about 5percent by volume of the total fluid. Correspondingly, the amount shouldnot be so great that it cannot be dispersed in the oleaginous phase.Therefore, typically the amount of non-oleaginous liquid is less thanabout 90, preferably less than about 80, more preferably less than about70 percent by volume of the total fluid.

According to a preferred embodiment, an additive of solid sized bariteparticles or sized weighting agents is added to a wellbore fluid. Thisgenerates a high density suspension with superior sag performance. Oneof skill in the art would understand that in addition to the sizedparticle weighting agents disclosed herein, one may add any of the knowndrilling or other wellbore fluid formulation additives such asemulsifiers, dispersants, oil-wetters, water-wetters, foamers anddefoamers to the fluid depending on the particular fluid requirementsand rheologies desired.

A drilling fluid is typically designed based on a number of technicalperformance and cost factors. The subject matters disclosed hereinenables the fluid to be tailored to suit the rheological and sagproperties as well as the cost element. The data reported herein showsthat the rheology of the drilling fluid is largely unaffected by theintroduction of sized barite weight material and that the sagperformance of the fluid is directly related to the particle size of theweight material used.

As previously noted although a preferred weighting agent is barite anaturally occurring mineral composed primarily of barium sulfate.Naturally occurring barite (barium sulfate) has been utilized as aweighting agent in drilling fluids for many years. Drilling grade bariteis often produced from barium sulfate containing ores either from asingle source or by blending material from several sources. It maycontain additional materials other than barium sulfate mineral and thusmay vary in color from off-white to grey or red brown. The AmericanPetroleum Institute (API) has issued international standards to whichground barite must comply. These standards can be found in APISpecification 13A, Section 2.

It is feasible to manufacture drilling or other wellbore fluids withother known minerals such as calcite (calcium carbonate), hematite (ironoxides), or ilmenite. According to a preferred illustrative embodiment,the weighting agent is formed of solid particles that are composed of amaterial having a specific gravity of at least 4.2. This allows awellbore fluid to be formulated to meet most density requirements yethave a particulate volume fraction low enough for the fluid to remainpumpable.

According to one illustrative embodiment, the weight average particlediameter of the weighting agent measures approximately 4 μm to 15 μm. Inanother illustrative embodiment, the weighting agent includes at least50% by weight particles in the range of about 1 μm to about 5 μm. And inanother illustrative embodiment, the weighting agent includes at least90% by weight particles in the range of about 4 μm to about 8 μm. Asshown in the examples below, use of these particle sizes enables one toachieve the objective of reducing sedimentation or sag potential withoutundesirably increasing the wellbore fluid viscosity.

According to another alternative illustrative embodiment the weightingagent is preferably barite and the sized barite weighting agent has aparticle size distribution such that at least 90% by volume of themeasured particle diameter is between about 4 μm and about 20 μm andpreferably is in the range of about 8 μm to about 16 μm. In thisillustrative embodiment, the sized barite weighting agent includes atleast 50% by volume particles is preferably in the range of about 1 μmto about 10 μm. and preferably in the range of about 4 μm to about 8 μm.

It has been found that a predominance of particles that are too fine(i.e. below about 1 μm) results in the formation of a high rheologypaste. Thus it has been unexpectedly found that the barite particlesmust be sufficiently small to avoid issues of barite sag and ECD, butnot so small as to have an adverse impact on rheology. Thus bariteparticles meeting the particle size distribution criteria disclosedherein may be utilized without adversely impacting the rheologicalproperties of the wellbore fluids. In one preferred and illustrativeembodiment a barite weighting agent is sized such that: particles havinga diameter less than 1 μm are 0 to 15% by volume; particles having adiameter between 1 μm and 4 μm are 15 to 40% by volume; particles havinga diameter between 4 μm and 8 μm are 15 to 30 by volume; particleshaving a diameter between 8 μm and 12 μm are 5 to 15% by volume;particles having a diameter between 12 μm and 16 μm are 3 to 7% byvolume; particles having a diameter between 16 μm and 20 μm are 0 to 10%by volume; particles having a diameter greater than 20 μm are 0 to 5% byvolume. In another alternative illustrative embodiment, the bariteweighting agent is sized so that the cumulative volume distribution is:<10% is less than 1 μm; <25% is in the range of 1 μm to 3 μm; <50% is inthe range of 2 μm to 6 μm; <75% is in the range of 6 μm to 10 μm; <90%is in the range of 10 μm to 24 μm.

A person skilled in the art should immediately appreciate that theparticle size distribution of the weighting agents disclosed herein isconsiderably finer than API barite. This is graphically shown in FIG. 1which shows the particle distributions of API barite and a barite groundin accordance with the teachings of the present invention (Barite A).

One may obtain particles of the dimensions disclosed herein in severalmanners. One may purchase, commercially, these sized particles, such asfor example, a suitable barite product having similar dimensions asdisclosed herein. Of course, one may also obtain a coarser groundsuitable material and then proceed to implement any known technique tofurther grind the material to the desired dimensions herein. Suchtechniques include jet-milling, high performance dry milling techniques,or any other technique that is known in the art generally for millingpowdered products. In one preferred embodiment, appropriately sizedparticles of barite are selectively removed from the product stream of aconvention barite grinding plant. This may include selectively removingthe fines from a conventional API barite grinding operation. The finesare often considered a by-product of the grinding process andconventionally these materials are blended with courser materials toachieve API grade barite. However, in accordance with the presentdisclosure, these by-product fines may be further process via a airclassifier to achieve the particle size distributions disclosed herein.

Given the particulate nature of the weighting agents disclosed herein,one of skill in the art should appreciate that additional components maybe mixed with the weighting agent to modify various macroscopicproperties. For example, anti-caking agents, lubricating agents, andagents used to mitigate moisture build-up may be included.Alternatively, solid materials that enhance lubricity or help controlfluid loss may be added to the weighting agents of the presentinvention. In one illustrative examples, finely powdered naturalgraphite, petroleum coke, graphitized carbon or mixtures of these areadded to enhance lubricity, rate of penetration and fluid loss as wellas other properties of the drilling fluid. Another illustrativeembodiment utilizes finely ground polymer materials to impart variouscharacteristics to the drilling fluid. In instances where such materialsare added, it is important to note that the volume of added materialshould not have an substantial adverse impact on the properties andperformance of the drilling fluids. In one illustrative embodiment,polymeric fluid loss materials comprising less than 5% by weight areadded to enhance the properties of the drilling fluid. Alternativelyless than 5% by weight of suitably sized graphite and petroleum coke areadded to enhance the lubricity and fluid loss properties of the fluid.Finally in another illustrative embodiment less than 5% by weight of aconventional anti-caking agent is added to assist in the bulk storage ofthe weighting materials.

The particulate materials as described herein may be added as aweighting agent in a dry form or concentrated as slurry in either anaqueous medium or as an organic liquid. As is known, an organic liquidshould have the necessary environmental characteristics required foradditives to oil-based drilling fluids. With this in mind it ispreferred that the oleaginous fluid have a kinematic viscosity of lessthan 10 centistokes (10 mm²/s) at 40° C. and, for safety reasons, aflash point of greater than 60° C. Suitable oleaginous liquids are forexample diesel oil, mineral or white oils, n-alkanes or synthetic oilssuch as alpha-olefin oils, ester oils, mixtures of these fluids, as wellas other similar fluids which should be well known to one of skill inthe art of drilling or other wellbore fluid formulation. In oneillustrative embodiment of the present subject matters disclosed herein,the desired particle size distribution is achieve via wet milling of thecourser materials in the desired carrier fluid.

The particles as described herein may comprise one or a combination ofseveral known weighting agents. In one illustrative embodiment, theweighting agent is selected from, but not limited to, barium sulphate(barite), calcium carbonate, dolomite, ilmenite, hematite or other ironores, olivine, siderite, or strontium sulphate as well as combinationsand mixtures of these and other weighting materials known to one ofskill in the art. As one of skill in the art should realize, manyfactors may determine which weighting agent is most appropriate in anygiven set of circumstances. Factors such as cost, availability, density,size, or power required for grinding may influence the choice of productused.

The sized particles may further be used in any wellbore fluid such asdrilling, cementing, completion, packing, work-over (repairing),stimulation, well killing, spacer fluids and other uses of high densityfluids such as in a dense media separating fluid or in a ship's or othervehicle's ballast fluid. Such alternative uses, as well as other uses,of the present fluid should be apparent to one of skill in the art giventhe present disclosure.

The following examples are included to demonstrate illustrativeembodiments of the claimed subject matter; they should not be construedas limiting the scope of the claimed subject matter or any claimthereof. Those of skill in the art should appreciate that the techniquesdisclosed in the examples that follow represent techniques discovered bythe inventor to function well in the practice of the claimed subjectmatter, and thus can be considered to constitute preferred modes for itspractice. However, in light of the present disclosure, those of skill inthe art also should appreciate that many changes can be made in thespecific disclosed embodiments that still obtain a like or similarresult without departing from the scope of the claimed subject matter.

All testing was conducted in accordance with American PetroleumInstitute (API) standards. Mixing was performed on a Silverson L2R Mixeror Hamilton Beach Mixer. The viscosity at various shear rates (inrotations per minute or rpm's) and other rheological properties wereobtained using a Fann viscometer. Mud weights were checked using astandard mud scale or an analytical balance. Fluid loss was measuredwith a saturated API high-temperature high-pressure (HTHP) fluid losscell. The particle size distributions of the samples were measured on aMalvern Mastersizer Microplus instrument (by weight measurements) or aCoulter LS230 (by volume measurements). Dynamic sag measurements wereobtained using a Fann 35 viscometer with a sag shoe insert, such asdisclosed in pending U.S. patent application Ser. No. 10/603849, filedJun. 25, 2003 and the publication entitled, “Improved Wellsite Test forMonitoring Barite Sag,” AADE Drilling Fluids Conference, Houston, Tex.,Apr. 6–7, 2004, both of which are incorporated by reference in theirentireties. Of course, similar results would be obtained using Fann 35viscometer without a sag shoe insert, and other known methods in the artfor measuring viscosity values. After 30 minutes at a shear rate of 100rpm at 120° F., measurements were obtained.

In expressing a metric equivalent, the following U.S. to metricconversion factors are used: 1 gal=3.785 litres; 1 lb.=0.454 kg; 1lb/gal=0.1198 g/cm³; 1 bbl-42 gal; 1 lb/bbl (ppb)=2.835 kg/m³; 1 lb 100ft² =0.4788 Pa.

In the following illustrative examples, EXAMPLE I, II and III, twoweighting agents having different particle size characteristics wereused in the formulation of three drilling fluids. Two of the drillingfluids have similar densities and compositions; the third drilling fluidhas a density and composition specifically designed for HTHPapplication. A comparison of exemplary performance results for thecoarser weighting agent and the sized weighting agent of one embodimentof the claimed subject matter is provided in TABLES 2–5 and summarizedbelow.

EXAMPLE I

TABLES 2 and 3 show performance data obtained using substantiallysimilar fluid formulations (MW 13.2 lb/gal and OWR 80/20) and twodifferent barite weighting agents of varying particle size distribution(PSD), characterized as “coarser” and “ultra-fine.” The coarser PSD ischaracterized by a D₅₀ (by weight) of 7 μm and D₉₀ (by weight) of 23 μm;the sized PSD is characterized by D₅₀ (by weight) of 3 μm and D₉₀ (byweight) of 6 μm, however, it should be clear that the sized PSD is notlimited in any manner to these examples described herein.

The conventional performance data of TABLE 2 demonstrate that therheology of the drilling fluid remains relatively constant regardless ofwhether the fluid is formulated with the coarser or finer barite. Inother words, in surprising contrast to the conventional belief in theart, there is no dramatic increase in rheological effects due to theintroduction of the sized particles and the concomitant increase inparticle-particle interactions.

Additionally, suitable HTHP filtration properties (ml per 30 minutes),electrical stability, and gel strength, indicating a suitable mudformulation, were achieved with both the coarser and finerbarite-containing fluids. Electrical Stability (ES) is a measure of thevoltage required to break the emulsion and gives an indication of thestability of the drilling fluid. It is generally accepted that thehigher the ES value, the more stable the fluid. Generally, an ES valueof 500 or greater indicates a suitable stability. The ES data shownbelow indicates stable, well-emulsified fluids. The rheological propertygel strength is measured when a fluid has been static and has had timeto “relax”. Gel strength measurements indicate whether particles withina fluid have formed an association, giving an indication as to thesuitability of the mud formulation. High gel strength tends to beundesirable as it means greater shearing stress is necessary to deformthe gel, while low gel strengths are also considered undesirable due totheir poor affinity for solids bearing. The gel strengths shown areacceptable in that they are not very low and they are not progressivewith time.

TABLE 2 Conventional Performance Data Fluid 1: MW 13.2 lb/gal; OWR 80/20VG Fann35 Rheology at 120° F. 10′/10″ Viscosity at various shear GelWeight PSD rates (rpm of agitation) Strength ES HTHP Material (byweight) Fluid 600 300 200 100 6 3 (lb/100 ft²) (v) @250° F. CoarserD₅₀ - 7 D₉₀ - 23 1 46 29 23 16 7 5 7/10 686 3.2 Barite 2 66 39 29 19 7 68/12 790 0.8 3 58 35 27 19 7 6 7/11 684 2.4 4 51 30 23 15 6 5 8/8  6832.8 Finer D₅₀ - 3 D₉₀ - 6 1 42 27 21 15 6 5 7/8  749 3.6 Barite 2 66 4031 20 7 6 7/8  985 1.0 3 60 39 31 21 9 8 9/10 714 3.6 4 50 31 24 17 7 56/12 667 3.6

The data presented in TABLE 3 shows the sag benefits achievable with thefiner barite exemplary of one embodiment of the claimed subject matter.Over a range of comparable rheologies, the dynamic and static sagperformance of the fluid formulated with the sized weighting agent issuperior to the fluid formulated with the coarser weighting agent. Asshown on TABLE 3, use of the sized weighting agent results in (1) alower density difference between the top and bottom of the fluid column,as demonstrated by a lower sag index during a static sag test, and (2) amuch lower dynamic sag. This means that using an sized weighting agent,in this case barite, offers greater scope for fluid optimization inorder to achieve both the desired sag and rheological properties.

TABLE 3 Sag Performance Data Fluid 1: MW 13.2 lb/gal; OWR 80/20 DynamicSag 3 rpm at 120° F. Static Sag Weight Rheology (lb/gal change after 60hrs at 250° F. Material at 120° F. per 30 min) Sag Index Free Oil (ml)Coarser barite 3 0.598 83 (by weight) 3 0.620 90 D₅₀ = 7 6 0.99 0.552 28D₉₀ = 23 6 1.14 0.561 13 5 1.34 0.550 5 Finer barite 4 0.07 0.527 60 (byweight) 4 0.00 0.546 44 D₅₀ = 3 5 0.07 0.522 24 D₉₀ = 6 8 0.09 0.520 146 0.04 0.512 6

Upon consideration of the above data, one of skill in the art shouldappreciate that use of the finer barite resulted in an observableimprovement in the sag index and a dramatic improvement in the dynamicsag potential with no appreciable change in rheological properties fromthose obtained using the coarser weighting agent. That is to say, theuse of fine barite in and of itself provides a beneficial effect on thesag potential, both static and dynamic, of the drilling fluid. This isin stark contrast to what has been the prevalent view in the art on theuse of finer particles in wellbore fluid weighting agents.

EXAMPLE II

TABLE 4 shows a similar set of data for another fluid having the same MW13.2 lb/gal and OWR 80/20 as in Example I above. However, while thefiner PSD remains at D₅₀ (by weight) of 3 μm and D₉₀ (by weight) of 6μm, the coarser PSD is characterized by a larger diameter D₅₀ (byweight) of 9 μm and D₉₀ (by weight) of 38 μm.

In this case, as in Example I, the fluids were found to have similarrheological profiles, and there was no significant difference in the gelstrengths observed. And in this case, as in Example I, the dynamic sagperformance for the fluid containing the sized weighting agentsignificantly exceeds that performance of the fluid containing thecoarser weighting agent.

TABLE 4 Conventional and Dynamic Sag Performance Data Fluid 2: MW 13.2lb/gal; OWR 80/20 VG Fann35 Rheology at 120° F. (rpm) 10′/10″ Viscosityat various shear rates Gel Dynamic Weight PSD (rpm of agitation)Strength Sag Material (by weight) Fluid 600 300 200 100 6 3 (lb/100 ft²)(dMW) Coarser D₅₀ - 9 D₉₀ - 38 Base 56 34 27 18 8 7 7/10 3.17 BariteSIZED D₅₀ - 3 D₉₀ - 6 Base 52 34 27 19 9 8 8/12 0.08 Barite

EXAMPLE III

The exemplary data shown in TABLE 5 were obtained for a so-called HTHPdrilling fluid formulation (MW 17 lb/gal and OWR 90/10) using the twodifferent barite-weighting agents, identified as “coarser” and “finer.”As in the preceding example, the coarser PSD is characterized by D₅₀ (byweight) of 9 μm and D₉₀ (by weight) of 38 μm, and the finer PSD ischaracterized by D₅₀ (by weight) of 3 μm and D₉₀ (by weight) of 6 μm. Inthis case, the effects of contamination are compared with both fluids.Generally, when a substance, such as clay, contaminates a wellbore fluidthe rheology of the fluid greatly increases. As demonstrated in Table 5,the rheology of the fluid containing finer weight material doesincrease, but not significantly more than the fluid containing coarserweight material.

TABLE 5 Conventional and Dynamic Sag Performance Data Fluid 3: MW 17lb/gal; OWR 90/10 VG Fann35 Rheology at 120° F. 10′/10″ Viscosity atvarious shear Gel Dynamic Weight PSD rates (rpm of agitation) StrengthSag Material (by weight) Fluid 600 300 200 100 6 3 (lb/100 ft²) (dMW)Coarser D₅₀ - 9 D₉₀ - 38 Base 79 42 31 20 7 6  7/21 2.22 Barite 20 ppbOCMA clay 129 71 52 32 8 7  8/37 10 v/v % Seawater 140 83 63 40 13 912/33 Finer D₅₀ - 3 D₉₀ - 6 Base 66 39 29 19 7 6 10/18 0.02 Barite 20ppb OCMA clay 126 75 56 36 12 11 17/35 10 v/v % Seawater 102 64 49 34 1312 16/30

Once again, the data demonstrate very similar rheological properties forthe two fluid formulations, even after the addition of non-reactiveclay, which was used to simulate the contamination of drill solids andseawater. And once again, the data clearly show the superior dynamic sagperformance achieved using the finer barite, rather than theconventionally employed coarser barite, as the weighting agent.

EXAMPLE IV

In the following illustrative example, drilling fluid were formulatedutilizing commercially available API grade barite, a sized bariteweighting agent in accordance with the present disclosure (Barite A), asized barite weighting agent with a fine grind distribution (Barite B),and a polymer coated sized barite weighting agent (Barite C) made inaccordance with the disclosure of published U.S. application No.20040127366 the contents of which are incorporated herein by reference.

The particle diameter distribution for each weighting agent was measuredon a by volume basis and exemplary data is provided in FIG. 1. Thefluids were formulated to minimize any differences in chemistry forformulation except for the weighting agent. All of the fluids had anidentical Synthetic Oil (C16 to C18 internal olefin) to Water ratio of80 to 20 and an overall density of 13 ppb. The following Table 6provides the specifics of the fluid formulations:

TABLE 6 API Fluid Formulation Barite Barite A Barite B Barite C IOC16–C18 (base fluid) As required VG PLUS, ppb 1.70 1.70 1.70 1.70 VGSUPREME, ppb 0.80 0.80 0.80 0.80 Lime, ppb 3.0 3.0 3.0 3.0 SUREMUL, ppb7.0 7.0 7.0 7.0 SUREWET, ppb 2.0 2.0 2.0 2.0 Brine 25% wgt CaCl₂, 18.0418.04 18.04 11.95 ppb* Water, bbl 0.145 0.145 0.145 0.095 ECOTROL, ppb0.50 0.50 0.50 0.50 Weighting Agent, ppb 283.01 283.01 283.01 375.98Drill solids, ppb** 15.0 15.0 15.0 15.0 RHEFLAT, ppb 1.25 1.25 1.25 1.25RHETHIK, ppb 0.75 0.75 0.75 0.75

The base fluids were mixed in the order listed on a Silverson mixer at6000 rpm over an hour while maintaining the temperature below 150° F.

In formulating the above fluids the following commercially availableproducts all available from M-I SWACO, Houston Tex. were utilized:

Material VG PLUS, ppb Organophilic bentonite clay VG SUPREME, ppbOrganophilic bentonite clay SUREMUL, ppb Fatty acid based emulsifierSUREWET, ppb Amido-amine based wetting agent ECOTROL, ppb Polymericfluid lose control agent RHEFLAT, ppb Proprietary mixture of poly fattyacids RHETHIK, ppb Polymeric Thickening agent

The simulated drill solids used were from Petrohunt, Marcantal#1-LM#20043541. The solids were ground up and used in lieu of labcontaminates such as Rev Dust or OCMA Clay.

It should be noted that attempts to formulate a drilling fluid utilizingBarite B were unsuccessful and resulted in a fluid having paste likeconsistency. Thus it was not possible to obtain meaningful rheologicalproperties. One of skill in the art would immediately understand andappreciate that such a formulation is not useful as a wellbore fluidusing current state of the art drilling practices and methods.

The following Table 7 provides exemplary rheological data for each mudformulation.

TABLE 7 Initial Rheology API Barite Mud Properties Initial Barite ABarite C Oil:Water Ratio 80:20 80:20 80:20 Mud Weight, ppg 13.0 13.013.0 Rheo Temp, ° F. 40 100 150 40 100 150 40 100 150 600 rpm 118 72 58120 74 58 140 65 48 300 rpm 69 45 39 72 49 40 80 40 30 200 rpm 51 35 3055 40 35 56 30 23 100 rpm 32 24 21 32 30 27 33 18 15 6 rpm 11 12 11 1617 17 5 4 4 3 rpm 10 11 11 16 17 17 4 4 4 PV, cps 49 27 19 48 25 18 6025 18 YP, lbs/100 ft² 20 18 20 24 24 22 20 15 12 10 Second Gel 12 13 1319 20 18 4 3 4 10 Minute Gel 39 31 36 36 40 33 37 30 36 HTHP @ 250° F.,ml 3.4 3.6 4.0 E.S., Vts @ 120° F. 782 891 1060

A sample of each initial mud formulation was subjected rolling heataging at 150 F for 16 hours. The following Table 8 provides exemplaryrheological data for each mud formulation.

TABLE 8 Rheology After Dynamic (Rolling) Heat Aging at 150° F. for 16hours API Barite Mud Properties AHR Barite A Barite C Oil:Water Ratio80:20 80:20 80:20 Mud Weight, ppg 13.0 13.0 13.0 Rheo Temp, ° F. 40 100150 40 100 150 40 100 150 600 rpm 157 74 55 110 91 63 150 94 63 300 rpm89 44 35 68 56 41 89 54 37 200 rpm 65 34 26 50 43 32 58 38 28 100 rpm 4022 18 34 28 23 30 21 16 6 rpm 13 10 10 14 12 12 5 5 5 3 rpm 12 10 10 1311 11 5 4 4 PV, cps 68 30 20 42 35 22 61 40 26 YP, lbs/100 ft² 21 14 1526 21 19 28 14 11 10 Second Gel 12 15 13 23 23 22 6 4 7 10 Minute Gel 3431 30 39 36 32 24 21 15 HTHP @ 250° F., ml 4.2 6.8 5.4 E.S., Vts @ 120°F. 398 523 798

A sample of each initial mud formulation was contaminated with anadditional 3% drill solids mixed on a Hamilton Beach mixer. Thesimulated drill solids used were from Petrohunt, Marcantal #1-LM#20043541. The solids were ground up and used in lieu of lab contaminatessuch as Rev Dust or OCMA Clay. These fluids were subjected rolling heataging at 150 F for 16 hours. The following Table 9 provides exemplaryrheological data for each mud formulation.

TABLE 9 Rheology After Dynamic (Rolling) Heat Aging at 150° F. for 16hours with 3% wgt additional drill solids Mud Properties API BariteBarite A Barite C Oil:Water Ratio 80:20 80:20 80:20 Mud Weight, ppg 13.013.0 13.0 Rheo Temp, ° F. 40 100 150 40 100 150 40 100 150 600 rpm 17382 57 131 106 72 152 98 65 300 rpm 95 48 34 78 63 44 88 53 36 200 rpm 6936 26 54 47 34 50 37 26 100 rpm 42 23 19 34 31 24 27 20 15 6 rpm 11 1010 14 12 11 5 3 3 3 rpm 11 9 9 13 11 11 4 3 3 PV, cps 77 34 23 53 43 2864 45 29 YP, lbs/100 ft² 19 14 11 25 20 16 24 8 7 10 Second Gel 12 12 1321 20 22 4 3 4 10 Minute Gel 38 32 30 34 37 33 29 23 27 HTHP @ 250° F.,ml 5.0 8.0 7.0 E.S., Vts @ 120° F. 404 600 705

A sample of each initial mud formulation was contaminated with anadditional 3% drill solids mixed on a Hamilton Beach mixer. Thesimulated drill solids used were from Petrohunt, Marcantal #1-LM#20043541. The solids were ground up and used in lieu of lab contaminatessuch as Rev Dust or OCMA Clay. These fluids were subjected static heataging at 150 F for 16 hours. The following Table 10 provides exemplaryrheological data for each mud formulation.

TABLE 10 After Static Heat Aging at 250° F. for 16 hours Mud PropertiesAPI Barite A Barite C Oil:Water Ratio 80:20 80:20 80:20 Mud Weight, ppg13.0 13.0 13.0 Rheo Temp, ° F. 150 150 150 600 rpm 49 43 47 300 rpm 3028 30 200 rpm 22 21 22 100 rpm 15 15 14 6 rpm 8 8 5 3 rpm 8 8 5 PV, cps19 15 17 YP, lbs/100 ft² 11 13 13 10 Second Gel 11 15 5 10 Minute Gel 2624 11

The variation in the mud weight (ΔMW) for the statically aged drillingfluid was measured by carefully extracting samples of the fluid from thetop, middle and bottom of the static fluid. The following Table 11provides exemplary results.

TABLE 11 Variation In The Mud Weight (ΔMW) For The Statically AgedDrilling Fluid ΔMW- Static API Barite A Barite C Top, ppg 12.92 13.013.01 Middle, ppg 13.12 13.12 13.10 Bottom, ppg 14.2 13.21 13.20

Upon review of the above data, one of skill in the art should understandand appreciate that a useful wellbore fluid can be formulated using asized barite weighting agent that has a particle size distribution wellbelow the API standard. It should also be appreciated that bycontrolling the particle size distribution of the barite weighting agentof the present disclosure, rheology can be controlled and a usefulwellbore fluid can be formulated which is in direct contrast to theteachings of the prior art. Further, it has been unexpectedly found thatdrilling fluids formulated with the sized barite weighting agent of thepresent disclosure do not exhibit the dynamic and static sag propertiespresent in fluids formulated with API grade barite.

One of skill in the art of drilling or other wellbore fluid formulationwill appreciate that it has been the general understanding thatdecreasing the particle size in weighting agents leads to acorresponding increase in viscosity, which is undesirable in theindustry. This was shown in the above example with a paste forming whenusing size Barite B. However, as supported by the above data, the use ofsized barite weighting agent as disclosed herein does not in fact leadto any appreciable difference in rheological properties from thoseobtained with coarser ground weighting agents. And in fact, as supportedby the above data, the use of sized weighting agent results insubstantial and observable improvements in both the static and dynamicsag potentials of a wellbore fluid.

In view of the above disclosure, a person skilled and knowledgeable inthe art of drilling fluids should understand and appreciate that oneillustrative embodiment of the present disclosure is a drilling fluidcomprising a fluid phase and a solid phase weight material forincreasing the density of the drilling fluid in which the weightmaterial is a ground particulate material and has a particle sizedistribution of at least 50% by weight particles in the range of about 1μm to about 5 μm and at least 90% by weight particles in the range ofabout 4 μm to about 8 μm. In one preferred embodiment of theillustrative fluid the solid phase weight material is selected from thegroup including barite, calcite, hematite, ilmenite or combinationsthereof and other similar material well know to one of skill in the art.The exemplary drilling fluid may be formulated such that the fluid phaseis an oleaginous fluid selected from diesel oil, mineral oil, syntheticoil such as polyolefins or isomerized polyolefins, ester oils,glycerides of fatty acids, aliphatic esters, aliphatic ethers, aliphaticacetals, and combinations thereof and other similar material well knowto one of skill in the art. Alternatively, the illustrative drillingfluid is formulated to include a fluid phase that is an invert emulsionin which the continuous phase is an oleaginous fluid selected fromdiesel oil, mineral oil, synthetic oil such as polyolefins or isomerizedpolyolefins, ester oils, glycerides of fatty acids, aliphatic esters,aliphatic ethers, aliphatic acetals, and combinations thereof and othersimilar material well know to one of skill in the art; and thediscontinuous phase is a non-oleaginous fluid selected from fresh water,seawater, brine containing inorganic or organic dissolved salts, aqueoussolutions containing water-miscible organic compounds and mixtures ofthese and other similar material well know to one of skill in the art.Additional additives such as those selected from additives forfiltration control, additives for high temperature pressure control,additives for rheology control and combinations thereof and othersimilar material well know to one of skill in the art, may optionally beincluded in the illustrative drilling fluid. A unique characteristic ofthe illustrative drilling fluid is that when the drilling fluid is usedin drilling operation such that sag is eliminated or avoided.

Another illustrative drilling fluid comprising a fluid phase and a solidphase weight material for increasing the density of the drilling fluid,wherein the weight material is a ground particulate material and has aparticle size distribution such that: particles having a diameter lessthan 1 μm are 0 to 15% by volume; particles having a diameter between 1μm and 4 μm are 15 to 40% by volume; particles having a diameter between4 μm and 8 μm are 15 to 30 by volume; particles having a diameterbetween 8 μm and 12 μm are 5 to 15% by volume; particles having adiameter between 12 μm and 16 μm are 3 to 7% by volume; particles havinga diameter between 16 μm and 20 μm are 0 to 10% by volume; particleshaving a diameter greater than 20 μm are 0 to 5% by volume. A thirdillustrative drilling fluid is formulated to include a fluid phase and asolid phase weight material for increasing the density of the drillingfluid, wherein the solid phase weight material is a ground particulatematerial and has a cumulative volume particle distribution such that<10% is less than 1 μm; <25% is in the range of 1 μm to 3 μm; <50% is inthe range of 2 μm to 6 μm; <75% is in the range of 6 μm to 10 μm; <90%is in the range of 10 μm to 24 μm. In both the two precedingillustrative fluids, the solid phase weight material is selected frombarite, calcite, hematite, ilmenite or combinations thereof, but ispreferably barite. Optionally the fluid phase of the illustrativedrilling gluids may be an oleaginous fluid selected from diesel oil,mineral oil, synthetic oil such as polyolefins or isomerizedpolyolefins, ester oils, glycerides of fatty acids, aliphatic esters,aliphatic ethers, aliphatic acetals, and combinations thereof and othersimilar material well know to one of skill in the art.

The present disclosure also encompasses a method of drilling asubterranean well utilizing a drilling fluids as substantially describedherein. In one such illustrative embodiment, conventional rotarydrilling operation are carried out utilizing a drilling fluid that isformulated to include a fluid phase and a solid phase weight materialfor increasing the density of the drilling fluid, wherein the weightmaterial is a particulate material and has a particle size distributionof at least 50% by weight particles in the range of about 1 μm to about5 μm and at least 90% by weight particles in the range of about 4 μm toabout 8 μm. The method is preferably carried out using a the solid phaseweight material selected from barite, calcite, hematite, ilmenite orcombinations thereof. and other similar material well know to one ofskill in the art, but preferably the solid phase weighting material isbarite.

It should also be appreciated that the present disclosure encompasses amethod of drilling a subterranean well utilizing a drilling fluid,wherein the drilling fluid is formulated to include a fluid phase and asolid phase weight material for increasing the density of the drillingfluid, wherein the weight material is a particulate material and has aparticle size distribution such that: particles having a diameter lessthan 1 μm are 0 to 15% by volume; particles having a diameter between 1μm and 4 μm are 15 to 40% by volume; particles having a diameter between4 μm and 8 μm are 15 to 30 by volume; particles having a diameterbetween 8 μm and 12 μm are 5 to 15% by volume; particles having adiameter between 12 μm and 16 μm are 3 to 7% by volume; particles havinga diameter between 16 μm and 20 μm are 0 to 10% by volume; particleshaving a diameter greater than 20 μm are 0 to 5% by volume.Alternatively the present disclosure encompasses an illustrativeembodiment in which a method of drilling a subterranean well utilizing adrilling fluid, wherein the drilling fluid comprises a fluid phase and asolid phase weight material for increasing the density of the drillingfluid, wherein the solid phase weight material is particulate and has acumulative volume particle distribution such that <10% is less than 1μm; <25% is in the range of 1 μm to 3 μm; <50% is in the range of 2 μmto 6 μm; <75% is in the range of 6 μm to 10 μm; <90% is in the range of10 μm to 24 μm.

In addition, one of skill in the art should appreciate that a method ofincreasing the density of a fluid phase of a drilling fluid is also anillustrative embodiment of the present disclosure. One such illustrativeincludes adding to the fluid phase of the drilling fluid a solid phaseweight material for increasing the density of the drilling fluid,wherein the solid phase weight material is a particulate material andhas a particle size distribution of at least 50% by weight particles inthe range of about 1 μm to about 5 μm and at least 90% by weightparticles in the range of about 4 μm to about 8 μm. Alternatively, theillustrative method may involve increasing the density of the drillingfluid, wherein the solid phase weight material is particulate materialand has a particle size distribution such that: particles having adiameter less than 1 μm are 0 to 15% by volume; particles having adiameter between 1 μm and 4 μm are 15 to 40% by volume; particles havinga diameter between 4 μm and 8 μm are 15 to 30 by volume; particleshaving a diameter between 8 μm and 12 μm are 5 to 15% by volume;particles having a diameter between 12 μm and 16 μm are 3 to 7% byvolume; particles having a diameter between 16 μm and 20 μm are 0 to 10%by volume; particles having a diameter greater than 20 μm are 0 to 5% byvolume. Yet a third variation to the disclosed illustrative methods is amethod of increasing the density of a fluid phase of a drilling fluid,the method comprising adding to the fluid phase of the drilling fluid asolid phase weight material for increasing the density of the drillingfluid, wherein the solid phase weight material is particulate materialand has a cumulative volume particle distribution such that: <10% isless than 1 μm; <25% is in the range of 1 μm to 3 μm; <50% is in therange of 2 μm to 6 μm; <75% is in the range of 6 μm to 10 μm; <90% is inthe range of 10 μm to 24 μm.

All of the methods and compositions disclosed and claimed herein can bemade and executed without undue experimentation in light of the presentdisclosure. While the methods and compositions disclosed herein havebeen described in terms of preferred embodiments, it will be apparent tothose of skill in the art that variations may be applied to the methods,and in the steps or in the sequence of steps of the methods describedherein and to the compositions and in the components of the compositionsdescribed herein. More specifically, it will be apparent that certainagents which are both chemically and physiologically related may besubstituted for the agents described herein while the same or similarresults would be achieved. All such similar substitutes andmodifications apparent to those skilled in the art are deemed to bewithin the scope and concept of the claimed subject matter as defined byany appended claims.

1. A method of increasing the density of a fluid phase of a drillingfluid, the method comprising adding to the fluid phase of the drillingfluid a solid phase weight material for increasing the density of thedrilling fluid, wherein the solid phase weight material is a particulatematerial and has a particle size distribution such that: particleshaving a diameter less than 1 μm are 0 to 15% by volume; particleshaving a diameter between 1 μm and 4 μm are 15 to 40% by volume;particles having a diameter between 4 μm and 8 μm are 15 to 30% byvolume; particles having a diameter between 8 μm and 12 μm are 5 to 15%by volume; particles having a diameter between 12 μm and 16 μm are 3 to7% by volume; particles having a diameter between 16 μm and 20 μm are 0to 10% by volume; particles having a diameter greater than 20 μm are 0to 5% by volume.
 2. The method of claim 1, wherein the solid phaseweight material is selected from the group consisting of barite,calcite, hematite, ilmenite or combinations thereof.
 3. The method ofclaim 1, wherein the solid phase weighting material is barite.
 4. Themethod of claim 1, wherein the fluid phase is an oleaginous fluidselected from the group consisting of diesel oil, mineral oil, syntheticoil such as polyolefins or isomerized polyolefins, ester oils,glycerides of fatty acids, aliphatic esters, aliphatic ethers, aliphaticacetals, and combinations thereof.
 5. The method of claim 1, wherein thefluid phase is an invert emulsion in which the continuous phase is anoleaginous fluid selected from the group consisting of diesel oil,mineral oil, synthetic oil such as polyolefins or isomerizedpolyolefins, ester oils, glycerides of fatty acids, aliphatic esters,aliphatic ethers, aliphatic acetals, and combinations thereof; and thediscontinuous phase is a non-oleaginous fluid selected from the groupconsisting of fresh water, seawater, brine containing inorganic ororganic dissolved salts, aqueous solutions containing water-miscibleorganic compounds and mixtures of these.
 6. The method of claim 1,wherein the drilling fluid further comprises at least one additionaladditive selected from the group consisting of additives for filtrationcontrol, additives for high temperature pressure control, additives forrheology control and combinations thereof.
 7. The method of claim 1,wherein the drilling fluid is used in drilling operation such that sagis eliminated or avoided.